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“Role of Induced and Natural 

Imbibition in Frac Fluid 

Transport and Fate

in Gas Shales”

Alan P. Byrnes

Chief Petrophysicst

Chesapeake Energy Corporation

6100 N. Western Avenue ı Oklahoma City, OK 76118 ı 405-935-8000

AskChesapeake@chk.com ı chk.com ı NYSE: CHK

Technical Workshops for Hydraulic Fracturing Study

Fate & Transport  March 28-29, 2011

US EPA Conference Center

One Potomac Yard (South Building)

2777 S. Crystal Drive 

Arlington, VA 22202 Room S-4370 and 4380

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Overview

• Hydraulic fracture (HF) models & production 

decay analysis support estimates of propped 

HF surface areas of 12 *106 sq ft and 

created area of 24-60 *106 sq ft. 

• Frac fluid 30+10% recovered/70+10% 

leaks off into the fracture face

• Elevated frac fluid saturations within 2 – 6 

inches of the frac face. 

• High capillary pressures in shales

• High frac-face Sw is not in equilibrium and 

capillary forces act to imbibe the fluid into 

the reservoir away from the frac face

• Frac fluids imbibed into the formation are 

effectively locked in place by capillary 

pressure forces of hundreds to thousands of 

pounds per square inch (psi) both during the 

life of the well production and for geologic 

periods of time after reservoir depletion

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CHK’s Operating Areas

Low-risk, U.S. onshore asset base; Not exposed to economic, geopolitical or 

technological risks internationally or in the Gulf of Mexico
Fate and Transport Issues

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• Basic Parameters

– Time: Near-term, Long-term

– Location: Reservoir, Wellbore, Surface

– Substance: Gas, Liquid(s)

Time Location Substance Time Location Substance

Near-term Surface Gas Long-term Surface Gas

Near-term Surface Liquid Long-term Surface Liquid

Near-term Wellbore Gas Long-term Wellbore Gas

Near-term Wellbore Liquid Long-term Wellbore Liquid

Near-term Reservoir Gas Long-term Reservoir Gas

Near-term Reservoir Liquid Long-term Reservoir Liquid

• This talk will focus on near- and long-term fate and transport 

of liquids in the reservoir (and wellbore)
Fracture Fluids & Proppant

• Frac Job Material Volumetrics

– Vary with operator, formation properties

– volumetrics shown are for a “large” job

• Proppant

– 5±2 *106lbs (~30±12 *103ft3)

– Mesh 100/40-70/20-40

• Frac Fluid

– 120±20 *103 bbls (675±100 *103ft3)

– “Slickwater” dominantly

– 3-11 chemical additives (all:1,000-6,000 ppmv)

• Friction reducer, biocide, KCl subsitute , Fe chelator

• Scale inhibitor, surfactant, non-emulsifier

• Gel, crosslinker, breaker, corrosion inhibitor

• All additives remain in Fluid except FR, Gel & XL

• Chesapeake Green FracTM

• Depth ( 1,500 ft, 1.5 sd)

• Barnett 7,400 ft

• Fayetteville 4,000 ft

• Haynesville 11,400 ft

• Marcellus 6,400 ft

• Target Reservoir Thickness 

• 200 100 ft

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(part per million volume)
Fracture Stimulated Rock Volume

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• Stimulated Rock Volume(SRV) 

geometry define by:

• Microseismic

• Frac material volumetrics

• Frac modeling

• Production Decline Analysis

•Parameters Involved

• Vertical stress profile

• Regional and local principal stress anisotropy

• Orientation of one/more natural fracture sets

• Rock elastic properties

• Fracture toughness

•Frac fluid properties

• Frac pump rates/pressures

• Times between injection period

• Proximity to frac barriers, nearby wells

• Reservoir rock properties

• Porosity

• Permeability

• Relative permeabilities

• Initial water saturations

• Capillary pressure properties

• Pore throat size distribution
Fracture Architectures

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(modified from Fisher et al, 2002)

• Example of range 

of fracture 

architectures for a 

single initiation 

site

• These would occur 

at each perf

cluster and so 

would be 

reproduced 

~50-70 times 

along the wellbore
Production Decline Analysis and Flow Simulation

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• Production Decline Analysis 

(PDA) & Numerical Flow 

Simulation Solve for A√k

• Inputing core analysis k

solve for A

• A = 12 *106ft2

• L = 4,700 ft

• Fracs= 66 (70-ft spacing)

• H=200 ft

• W=400 ft

• 2 sides of frac

• This surface area required for flow 

rates observed in wells

• 66 pairs of football fields

• Flow into both faces

Simple flow simulation showing 

initial intrafrac flow followed by 

interwell flow
Created vs Effective: Proppant Distribution

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• Fracture Models

• MFRAC/MSHALE (Meyer & Assoc.)

• Volumetrics support 12 *106ft2for 

effective propped frac surface area

• Effective propped fracture 20%-50% total 

fracture

• Models differ but surface area into which 

frac fluids are injected is approximately 

the same for all three architectures. 

(DFN Figures courtesy of Meyer & Assocs. MSHALE)
Frac Surface Area – Induced Imbibition

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• 12 *106ft2 Propped Effective

• Estimated Effective/Total

• 20%-50% →

• Total Frac Surface

• 24-60 *106ft2

• 120,000 bbls (670,000 ft3) of 

frac fluid pumped

• Assuming uniformly injected 

• Variable = f(t)

• Porosity f = 0.06

• Saturation depth ≈ 2 - 6 inches 

q(t) = 4 ∫ C/(t-to)

0.5 dA

q(t) = fluid loss rate at time t

A(t) = fracture area of one face

C = total leakoff coefficient

to = time of fracture area creation 

A(t)

0

• Simple 1D Leakoff Model
Porosity & Kerogen Properties

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ftotal = fintergranular + fintrakerogen

Py

I

Cc

QF

kerogen

Laminated argillaceous to 

calcareous mudstone to 

silty mudstone

Q

• Porosities vary by play and within reservoir intervals

• 3-10%

• General value 6%
Pore Throat Diameter vs. Permeability

• Permeability for all lithology rocks is principally controlled by pore throat size (the “chokes” in the flow path)

• For Mudstones of present commercial interest (50 nD < k < 2,000 nD) corresponding Dpt are 0.01 mm < Dpt < 0.2 mm

• “Typical” pore throat size distribution ranges from 10-20X so for 500 nD rock 0.004 mm < Dt < 0.09 mm

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(after Byrnes, 1997, 2005)

0.001

0.01

0.1

1

10

100

0.000001 0.00001 0.0001 0.001 0.01 0.1 1 10 100

Principal Pore Throat Diameter (um)

In situ Klinkenberg Permeability (md)

Undifferentiated

Non-Hugoton Sandstones

0-NM vf Sandstone

1-NM crs Siltstone

2-NM vf-med Siltstone

3-Marine Siltstone

4-Mud/Mud-Wkst

5-Wksn/Wkst-Pkst

6-Dol Sltst

7-Pkst/Pkst-Grnsn

8-Grnsn-PhAlgBafflest

9-Crs Dol

10-Marine vf Sandstone

{

Human

hair
Threshold Entry Pressures

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•Threshold entry capillary 

pressures (Pte) for lithic

sandstones (blue squares) and 

representative gas shales (open 

triangles).

•Pte were measured using air-Hg 

and converted to equivalent 

reservoir CH4-Brine pressures. 

•Data for shale show continuity 

with trend for sandstones and 

siltstones. Relationship can be 

expressed: 

•Pte = 8.6 ki

-0.424

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10

100

1000

0.000001 0.00001 0.0001 0.001 0.01 0.1 1 10 100 1000

Reservoir Methane-Brine Threshold Entry 

Capillary Pressure (psia)

In situ Klinkenberg Permeability (mD)

(modified from Byrnes 2009)
Gas Shale vs

Low-k Sandstone 

Capillary Pressure

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1 0

100

1000

10000

0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0

In situ Methane-Brine 

Capillary Pressure (psia)

Wetting Phase Saturation

Low K

High K

Water Imbibition

General Imbibition

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10

100

1000

10000

0 10 20 30 40 50 60 70 80 90 100 Insitu Methane-Brine Capillary Presure (psia)

Wetting Phase Saturation (%)

0.00049md

0.0012md

0.0017md

0.0018md

0.0030md

0.0040md

0.0057md

0.0085md

0.012md

0.013md

0.032md

0.046md

0.085md

0.25md

0.41md

0.56md

0.84md

2.24md

• Theshold entry pressure (Pte) 

increase with decreasing 

permeability

• Gas shales exhibit higher 

threshold entry pressures 

consistent with texture and 

permeability

• Capillary pressure distribution is 

approximately 10X-20X from Pte

Ki=0.001 mD

Ki=0.0001 mD
Shale Capillary Pressure Properties

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1 0

100

1000

10000

0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0

In situ Methane-Brine 

Capillary Pressure (psia)

Wetting Phase Saturation

Low K

High K

Water Imbibition

General Imbibition

• 0.002 mD > ki > 0.00005 mD

• 120 psi < Pte < 600 psi

• Pc increases with decreasing 

water saturation.

• Capillary pressures (Pc) 

required to achieve or maintain 

the brine saturations in the 

present-day reservoirs (0.2 < Sw

< 0.5) do not exist in all 

reservoirs today.

Ki=0.0001 mD

Ki=0.001 mD

• Capillary pressure properties of present day reservoir do not necessarily 

represent conditions at time of desaturation

• reservoir exhibited better properties at time of gas generation allowing desaturation at 

lower Pc

• Present Reservoir 

• Nonequilibrium and undersaturated

• Equilibrium but has mixed or intermediate wettability.

• Natural imbibition of water to Sw>0.75 for gas shale cores tested (black circles)

• requires reservoir is sufficiently water wet to imbibe water with change in capillary 

pressure conditions

• Imbibition curves, based on low-k sandstone, show general path of imbibition Pc curve
Shale Capillary Pressure Properties

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1 0

100

1000

10000

0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0

In situ Methane-Brine 

Capillary Pressure (psia)

Wetting Phase Saturation

Low K

High K

Water Imbibition

General Imbibition

• After frac for 2-6 inches into the 

formation from the frac face Sw

is~100%

• Reservoir Sw ~30%

• Capillary pressure difference 

between these two Sw states is 

100’s-1,000’s of psi

Ki=0.0001 mD

Ki=0.001 mD

• Capillary pressure difference between the reservoir and the frac face causes 

frac fluids to move to reservoir – natural imbibition

• System is driven by Pc to uniform saturation state 

• to achieve uniform Sw the high Sw in frac-face region must imbibe

• Rate of movement; q(t) = f(kew, Sw, Pc, f) 

Reservoir Pc

Frac Face Pc

}

ΔPc
Fate of Frac Fluids

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• Initial production produces 30 10% of frac fluid

• Remaining 70 10% of fluid leaks off into formation

• If well is shut in natural imbibition works unhindered

• If well is placed on production immediately then viscous 

forces and low near-frac face pressures slow or halt natural 

imbibition

• As near-frac face region gas pressures drop the lower Pc 

condition “locks” in the Sw state and fluids are held in place

• With complete pressure depletion of the well the low Pc 

condition of the reservoir traps all fluid in place

• In pressure depleted state the reservoir is undersaturated

and over geologic time acts to imbibe water
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Conclusions

• Hydraulic fracture modeling and fracture surface area 

calculations determined from pressure decay analysis and 

reservoir numerical flow simulation support. estimates of 

created hydraulic fracture surface areas of 24-60 *106 sq ft. 

• 30+10% of the frac fluids are recovered.

• 70+10% leaks off into the fracture face resulting in elevated 

frac fluid saturations within ~2 – 6 inches of the frac face. 

• High frac-face Sw is not in equilibrium and capillary forces act 

to imbibe the fluid into the reservoir away from the frac face

• Frac fluids imbibed into the formation are effectively locked 

in place by capillary pressure forces of hundreds to thousands 

of pounds per square inch (psi) both during the life of the well 

production and for geologic periods of time after reservoir 

depletion. 

• Further research is needed and is ongoing as to the exact 

shape of the imbibition capillary pressure curves and 

imbibition water relative permeability curves to fully quantify 

the imbibition process and timing. 
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“Thank You – Questions?”

Alan P. Byrnes

Chief Petrophysicst

Chesapeake Energy Corporation

6100 N. Western Avenue ı Oklahoma City, OK 76118 ı 405-935-8000

AskChesapeake@chk.com ı chk.com ı NYSE: CHK 19